For modeling gas production from reservoirs, laboratory tests may be performed on samples from the reservoir. Such tests may include determining porosities and absolute permeabilities. Determining porosity may allow for a prediction of an amount of hydrocarbons that may be stored in the porous material. Determining permeability may allow for a prediction of the rate at which a fluid will flow at a given pressure.
In modeling, failure to account for the impact of non-inertial, non-Darcy phenomena, also known as microflows, may lead to errors when attempts are made to model gas production from ultra-low permeability reservoirs such as some shale reservoirs or to interpret results from laboratory tests where a gas is flowed through a sample of material, such as mesoporous material, from these types of reservoirs. Knowledge of the absolute permeability and porosity alone of a porous material may be insufficient to accurately and effectively model flow through a reservoir, particularly when the permeability of the reservoir is ultra-low. Indeed, in some shale specimens, non-inertial, non-Darcy flows may cause the effective permeability of gases to be greater than the absolute permeability. This may cause inaccurate modeling of gas flow through such specimens.
Pore size distribution within porous media may be determined to aid in properly characterizing porous media whose absolute permeabilities are small, such as below one microdarcy. Such porous media are referred to herein as ultra-low permeability media.
In the past, some attempts have been made to measure the pore structure on whole cores with methods involving nitrogen adsorption coupled with mercury intrusion with typically mercury injection capillary pressure (MICP) measurements. These methods were destructive to the cores and thus costly, and they were typically also time consuming.
Another method to determine pore size distribution included nitrogen adsorption. Such a method required the sample be cooled to a very low temperature of 77 K.